Water is naturally present in most subterranean formations of depositional origin including, without limitation, oil and gas reservoirs and coal deposits. In certain circumstances, it is desirable to displace water from a region near a wellbore in order to use treatment chemicals or procedures that may be adversely affected by excessive water, either through dilution or interference with the desired reaction. Examples of procedures that generally benefit from reduced water saturation in the near-well region include sand consolidation and polymer squeeze jobs, as well as other techniques that would benefit from greater contact with the reservoir matrix. In other circumstances, displacement of the water may itself be the desired treatment result. For gas injection used in tertiary recovery processes and other applications, educing the water saturation in the near-well region has a significant beneficial impact on gas injectivity. As used herein, the "near-well region" means that region in the vicinity of a wellbore the properties of which generally affect the flow of fluids into or out of the wellbore itself (as opposed to general reservoir flow patterns), usually, but not limited to, a radius of approximately two to as much as about fifty feet around the wellbore.
Although sand consolidation is no longer widely used, patents and publications from the 1970s suggest a variety of specific solvents to preflush the formation for water removal. Water interfered with successful sand consolidation more than oil, but oil removal was a secondary objective in many of the preflush proposals. The primary focus in selecting preflush solvents for sand consolidation work was on miscibility with both water and oil, with much of the selection process actually growing out of efforts to remove oil from the near-well region.
Several patented processes have also been presented for conditioning the near-well region for the purpose of acidizing the formation, with the focus in these patents being on oil removal to avoid the formation of emulsions during or after treatment. Few existing patents have addressed procedures focussed on the reduction of water saturation, especially as it relates to non-oil-bearing formations such as gas reservoirs or even aquifers. In itself, reduction of water saturation in the near-well region as a conditioning step before treatment will reduce dilution of treatment chemicals, allow better contact with the formation, and allow the use of treatments incompatible with water. In other cases, reduction of water saturation in the near-well region improves the relative permeability of the formation to oil, gas, or any other nonaqueous fluid. Changing relative permeabilities affects the potential recovery of oil or gas from a reservoir.
A significant amount of the crude oil contained in a subterranean formation is left in place after primary and secondary recovery processes. The crude oil left behind after secondary recovery processes can be as high as 20 to 50% of the original oil in place (OOIP). Water will also be present in the reservoir, as naturally occurring connate water, as a result of natural water drive, or as a result of injection for artificial water-flooding. Water as used herein will include any of the above, as well as fresh water, artificial brine, or any aqueous solution (e.g., solutions containing surfactants, polymers, acid, or any other additives) which might have been injected into the reservoir formation. Water saturation, S.sub.w, is expressed as a percentage of the relevant reservoir pore volume, herein generally a percentage of the near-well pore volume.
Various tertiary recovery processes using solvents, chemicals, polymers, heat (including steam), or foams have been proposed or used to recover an additional percentage of the OOIP by improving the relative flow characteristics of the reservoir fluids and/or by sweeping reservoir fluids toward a production well. The economic and/or physical effectiveness of these processes often depends on maximizing contact with the remaining oil in the minimum possible time. Balancing maximum contact with minimum time makes the injectivity of the tertiary recovery materials into the reservoir a critical factor. Of course, the economics for any particular process are also dependent on the cost of the materials required. While solvents, chemicals, polymers, and surfactants, including those used to generate foams, vary in cost, the ready availability of carbon dioxide or natural gas often lead to lower cost per barrel of oil recovered than for other processes.
The objective of tertiary recovery processes is to reduce the residual oil saturation in the reservoir to its lowest possible value, thereby maximizing recovery of the OOIP. Residual oil saturation depends on the capillary number (defined more fully below), which in turn is dependent on fluid velocity, viscosity, and interfacial tension. As used herein, capillary number is an expression representing how readily a given fluid flows through the restricted pore spaces in the reservoir relative to the other fluids present. For example, miscible and near-miscible solvents blend with oil to reduce viscosity and eliminate (or significantly reduce) interfacial tension, thus maximizing the capillary number for the oil, which in turn leads to decreased residual oil saturation.
Solvent miscible flooding uses solvents that are either miscible with or near-miscible with the crude oil left behind by primary and secondary recovery processes. Some examples of solvents which could be used in miscible flooding include natural gas, methane, ethane, other natural gas components, condensate, alcohols, ketones, micellar solutions, carbon dioxide, nitrogen, flue gas and combinations of these. Generally, both economics and commercial availability make solvent gases more attractive than liquid solvents for use in miscible flooding. However, oil recovery from solvent gas processes is negatively impacted by the unfavorable mobility and density ratios between the oil and solvent gas, which lead to poor sweep efficiency. Specifically, an unfavorable mobility ratio between the gas and the oil allows solvent gas fingering or channeling resulting in low oil recoveries because not all of the residual oil is contacted by the solvent gas. Likewise, unfavorable density ratios can cause the solvent gas to migrate to the top of the reservoir bypassing much of the crude oil.
Often water injection is alternated with the solvent gas injection to mitigate the poor sweep performance of a solvent gas process. This process is called a Water-Alternating-Gas (WAG) process. A solvent process has better sweep when the water and solvent flow together in a commingled zone because water has a lower mobility ratio with respect to oil than the solvent gas does. The water tends to help sweep both the oil and the solvent gas through the reservoir. In a WAG process, the fraction of the reservoir swept by the solvent gas (the commingled zone) is proportional to the injection rate of the solvent gas. Therefore, increasing the injection rate can increase the sweep efficiency of a WAG process.
A more expensive alternative used to address the problems with sweep efficiency in WAG processes is to use a Surfactant-Alternating-Gas (SAG) process to generate foam in the reservoir. Foam in tertiary recovery projects reduces gas mobility in the reservoir, improving sweep efficiency more than water alone. Foam has the added advantage of preferentially reducing gas mobility in high permeability areas of the reservoir, further improving sweep efficiency in the lower permeability portions of the reservoir. In these situations, foam duration, or stability, is a desirable characteristic for sweep improvement. The disadvantage to using SAG is the added cost of the surfactant.
In addition to improving sweep efficiency in a WAG or SAG process, increasing the solvent injection rate accelerates the rate at which the oil is produced because the injected solvent more quickly enters the reservoir, contacts, and displaces the oil. Both increasing the oil recovery and accelerating the oil production are advantageous and will significantly improve the economic viability of a given recovery process.
Therefore, it is usually desirable to inject the gas (generally referred to herein as "primary solvent gas" to distinguish it from other fluids discussed) in a solvent gas process at the highest rate possible. The injection rate for the primary solvent gas, Q.sub.psg, is determined by the following expression. EQU Q.sub.psg =I.sub.psg (P.sub.psg -P.sub.res) (1)
In equation 1, I.sub.psg is the injectivity for the primary solvent gas, P.sub.psg is the injection pressure for the primary solvent gas, and P.sub.res is the reservoir pressure. Injection rates, Q, are expressed in units of volume per unit of time (e.g., standard cubic feet/day or barrels/day), P is expressed in units of pressure (e.g., psi), and I is expressed in the appropriate rate units over pressure (e.g. standard cubic feet/day/psi or barrels/day/psi). Therefore, a large injectivity, I.sub.psg, indicates that a relatively high injection rate, Q.sub.psg, can be sustained with a relatively low pressure difference between the pressure at which the primary solvent gas is injected, P.sub.psg and the reservoir pressure, P.sub.res.
Although higher injection rates can be achieved by increasing the injection pressure, injection wells in most reservoirs are already operated near the maximum allowable well injection pressure. Increasing the injection pressure can lead to uncontrolled fracturing of the reservoir formation, which can cause a substantial reduction in oil recovery by causing diversion of the gas flow through the high permeability fracture or communication with other zones. Excessive pressure can also cause failure of the casing or other wellbore equipment. Therefore, there is a need for a method that can increase solvent injection rates without requiring an increase in injection pressure.
Currently the principal method of solvent-gas injection in a WAG process is to inject the solvent gas at a given wellhead pressure. This pressure is often determined by the limitations of the casing and other wellbore equipment, surface facilities, pipelines, and pumps. Injection pressure is also limited because it is generally not desirable for the pressure in the near-well region to be so high as to fracture the formation.
In a typical WAG process, water and solvent are injected in alternating cycles that last from about one week to many months. Within each cycle, solvent gas is injected to extract some portion of the oil from the rock and water is injected to displace the solvent gas and oil solution. Solvent injection volumes are generally expressed as a percentage of the reservoir pore volume. Typically, the volume of solvent injected into a given injection well during each cycle is about 1% to 5% of the pore volume targeted to be swept by injections into that well. In the near-well region, the oil saturation will generally be very low, often less than 15%, because large volumes of water at high flow rates have contacted the pore space. At the beginning of each solvent cycle, the water saturation in the near-well region may be as high as 65%-95% because water has just been injected. Therefore, the gas saturation may be as low as 5%-20% (with the remainder accounted for by any residual oil present), and the solvent gas mobility and corresponding injectivity are also low (explained more fully below). If, at the beginning of each solvent cycle, the water saturation were lower, both the solvent gas mobility and its injectivity would be greatly increased. With high water saturation, the gas is effectively blocked from flowing.
Currently one method used to increase solvent gas injectivity in a WAG process is to fracture the reservoir formation around the well. The fracture permits a solvent gas to be injected at a significantly higher rate because large flow paths are created that increase the injectivity when the fracture is formed. As noted above, however, the disadvantage of such a method is that fractures are difficult to control. An incorrectly placed fracture can cause the solvent gas to bypass much of the oil in place in the reservoir formation and decrease oil production. Therefore, fractures are usually avoided. In fact, much of the literature regarding solvent injection relates to methods of controlling mobility to limit the volume sweeping higher permeability portions of the reservoir. Uncontrolled fractures are an example of a very high permeability region that would take large volumes of solvent. Mobility control in higher permeability portions of the reservoir is one of the significant benefits of SAG and other foam flood processes.
A second method for increasing solvent gas injectivity is to inject acid into the reservoir formation around the near-well region. The acid will dissolve debris that can impede the flow of any injected gas. Once such debris is dissolved, the injectivity rate may be increased. While this method is useful, the extent to which acid can improve injectivity is generally limited to the extent that it removes debris from the wellbore area. Even with the removal of this debris, solvent injectivity may remain low because of the relative permeability effects discussed earlier. Acid injection also has the negative side effect of leaving the near-well region saturated with an aqueous liquid. Therefore, injecting acid to improve solvent injectivity has limited application.
A third method to increase solvent gas injectivity is to inject solvent for an extended period. As large volumes of unsaturated solvent contact the water over time, some vaporization occurs, effectively removing some of the water from the near-well region. This will increase the gas saturation and hence increase the gas injectivity (described below). Although injectivity improves over time, this process may take many months and significant volumes of solvent injection to remove sufficient water to achieve maximum gas injectivity. Thus, for much of the solvent injection cycle, solvent is being injected with a low injectivity. With the solvent injection cycle lengths in a typical WAG process, solvent gas injectivity can never reach its maximum value. A dramatic example of the change in solvent gas injectivity during the cycle is shown in FIG. 2, which depicts solvent injectivity 6 (solid line) and water injectivity 8 (dashed line) versus time over several cycles of a WAG flood. The solvent used in this example was carbon dioxide which is reported in barrels per day for comparison with reservoir pore volumes and water injection volumes. In FIG. 2, it can be seen that the solvent gas injection cycles are shorter than the time required for the gas injectivity 6 to stabilize at its maximum value. Since the desired water/solvent commingled zone will not form until water is injected, an extended solvent injection cycle would significantly delay formation of the commingled zone. This delay would reduce the sweep efficiency benefits of the WAG process.
A similar improvement in injectivity during the gas injection cycle was noted by W. R. Rossen, et al. in SAG modeling work (Injectivity and Gravity Override in Surfactant-Alternating-Gas Foam Processes, SPE 30753 presented at the SPE Annual Technical Conference, Dallas, October 1995), which indicated maximum injectivity after about 0.6 or more reservoir pore volumes of gas injection. Rossen, et al. theorized that over time, the injected solvent gas evaporated water from the foam lamellae in the near-well region causing the foam in that region to break down. With stable foams, there is still a significant period in which gas injectivity is less than optimal while the foam breaks down. Stable foams are generally desirable for the success of SAG processes.
Accordingly, there is a need for a method for reducing the water saturation in the near-well region to facilitate formation treatments such as sand consolidation and improvement of solvent injectivity to enhance the amount and/or rate of hydrocarbon recovery from a formation. The present invention provides an economical solution to this need.